Systems and methods for producing oil and/or gas

ABSTRACT

A method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer; drilling at least one horizontal production well near a top of the oil column; performing primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a location between the horizontal production well and a bottom of the oil column; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production well from the oil column.

FIELD OF THE INVENTION

The present disclosure relates to systems and methods for producing oil and/or gas.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields worldwide. There are three main types of EOR, thermal, chemical/polymer and gas injection, which may be used to increase oil recovery from a reservoir, beyond what can be achieved by conventional means—possibly extending the life of a field and boosting the oil recovery factor.

Thermal enhanced recovery works by adding heat to the reservoir. The most widely practiced form is a steamdrive, which reduces oil viscosity so that can flow to the producing wells. Chemical flooding increases recovery by reducing the capillary forces that trap residual oil and/or by reducing the interfacial tension between oil and water. Polymer flooding improves the sweep efficiency of injected water by more closely matching the oil and injectant viscosity and mobility ratio. Miscible injection works by creating a mixture of the injectant and the oil that flows more easily towards the production well than the oil by itself.

Referring to FIG. 1, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and terminates in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation portion 114 through well 112, to production facility 110. Well 112 has vertical portion 112 a and inclined portion 112 b. Gas and liquid are separated from each other, gas is stored in gas storage 116 and liquid is stored in liquid storage 118.

U.S. Patent Application Publication Number US 2009/308609 discloses a system comprising a well drilled into an underground formation; a production facility at a topside of the well; a water production facility connected to the production facility; wherein the water production facility produces water by removing some ions and adding an agent which increases the viscosity of the water and/or increases a hydrocarbon recovery from the formation, and injects the water into the well. U.S. Patent Application Publication Number US 2009/308609 is herein incorporated by reference in its entirety.

U.S. Patent Application Publication Number US 2008/194434 discloses the use of water-soluble polymers for tertiary mineral oil production by introducing the polymer into a mineral oil deposit, in which the water-soluble polymers are used in the form of a dispersion of the water-soluble polymer and at least one water-soluble, polymeric stabilizer. U.S. Patent Application Publication Number US 2008/194434 is herein incorporated by reference in its entirety.

There is a need in the art for improved systems and methods for enhanced oil recovery. There is a further need in the art for improved systems and methods for enhanced oil recovery using a polymer flood, for example through increased viscosity of the injectant, and/or other chemical effects. There is a further need in the art for improved systems and methods for polymer flooding. There is a further need in the art for improved systems and methods for polymer flooding with horizontal producers and horizontal injectors. There is a further need in the art for improved systems and methods for increasing the oil recovery of a formation supported by an aquifer. There is a further need in the art for improved systems and methods for increasing the oil recovery of a formation with horizontal completions at the top of the pay zone/oil column.

SUMMARY OF THE INVENTION

In one embodiment, the invention provides a method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer; drilling at least one horizontal production well near a top of the oil column; performing primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a location between the horizontal production well and a bottom of the oil column; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production well from the oil column.

Advantages of the invention include one or more of the following:

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a polymer flood.

Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a fluid containing a dissolved polymer.

Improved compositions and/or techniques for secondary and/or tertiary recovery of hydrocarbons.

Improved systems and methods for enhanced oil recovery.

Improved systems and methods for enhanced oil recovery using a compound which has an increased viscosity compared to water.

Improved systems and methods for polymer flooding with horizontal producers and horizontal injectors.

Improved systems and methods for increasing the oil recovery of a formation supported by an aquifer.

Improved systems and methods for increasing the oil recovery of a formation with horizontal completions at the top of the pay zone/oil column

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil and/or gas production system.

FIGS. 2 a and 2 b illustrate a well pattern.

FIGS. 2 c and 2 d illustrate the well pattern of FIG. 2 a during enhanced oil recovery processes.

FIG. 3 illustrates oil and/or gas production systems.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 2 a:

Referring now to FIG. 2 a, in some embodiments, an array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In one embodiment, array of wells 200 are vertical wells. In another embodiment, array of wells 200 are horizontal wells. In still a further embodiment, array of wells 200 may be inclined at an angle between vertical and horizontal.

Array 200 defines a production area, enclosed by the rectangle. Array 200 is within area 220 which is within the oil column or pay zone. Area 220 is located above area 222, which may be an aquifer.

Each well in well group 202 has horizontal distance 230 from the adjacent well in well group 202. Each well in well group 202 has vertical distance 232 from the area 222.

Each well in well group 204 has horizontal distance 236 from the adjacent well in well group 204. Each well in well group 204 has vertical distance 238 from the area of 222.

As shown in FIG. 2 a, horizontal distance 230 and horizontal distance 236 refer to a distance from left to right of the paper, and vertical distance 232 and vertical distance 238 refer to a distance from up to down of the paper. In practice, array may be composed of vertical wells that are perpendicular to the earth's surface, horizontal wells that are parallel to the earth's surface, or wells that are inclined at some other angle, for example 30 to 60 degrees with respect to the earth's surface.

Each well in well group 202 is distance 234 from the adjacent wells in well group 204. Each well in well group 204 is distance 234 from the adjacent wells in well group 202.

In some embodiments, each well in well group 202 is located above the two wells in well group 204. In some embodiments, each well in well group 204 is located below two wells in well group 202.

In some embodiments, horizontal distance 230 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, vertical distance 232 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, vertical distance 238 is from about 5 to about 500 meters, or from about 10 to about 250 meters, or from about 15 to about 125 meters, or from about 20 to about 50 meters, or from about 25 to about 75 meters, or from about 30 to about 40 meters.

In some embodiments, vertical distance 238 is from about 15% to about 90% of vertical distance 232, or from about 25% to about 75%, or from about 35% to about 60%.

In some embodiments, horizontal distance 236 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.

In some embodiments, distance 234 is from about 15 to about 750 meters, or from about 20 to about 500 meters, or from about 25 to about 250 meters, or from about 30 to about 100 meters, or from about 35 to about 75 meters, or from about 40 to about 50 meters.

In some embodiments, array of wells 200 may have from about 10 to about 1000 wells or a larger number of wells as needed for a development, for example from about 5 to about 500 wells in well group 202, and from about 5 to about 500 wells in well group 204.

In some embodiments, array of wells 200 is seen as a top view with well group 202 and well group 204 being vertical wells spaced on a piece of land. In some embodiments, array of wells 200 is seen as a cross-sectional side view with well group 202 and well group 204 being horizontal wells spaced within a formation.

The recovery of oil and/or gas with array of wells 200 from an underground formation may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production. The selection of the method used to recover the oil and/or gas from the underground formation is not critical.

In some embodiments, oil and/or gas may be recovered from a formation into a well, and flow through the well and flowline to a facility. In some embodiments, enhanced oil recovery, with the use of a polymer mixture for example a mixture of water and a polymer, may be used to increase the flow of oil and/or gas from the formation.

FIG. 2 b:

Referring now to FIG. 2 b, a cross-sectional view of FIG. 2 a taken along the line a-a is shown. FIG. 2 b shows array of wells 200 with horizontal production well 202 and horizontal injection well 204.

Wells 202 and 204 are located in oil column 220 located above aquifer 222. Oil column 220 has height 250, for example from about 10 m to about 200 m, or from about 20 m to about 100 m, or from about 30 m to about 60 m in height.

Production well 202 is a height 232 above the interface between oil column 220 and aquifer 222 for example from about 10 m to about 200 m, or from about 20 m to about 100 m, or from about 30 m to about 60 m in height.

Injection well 204 is a height 238 above the interface between oil column 220 and aquifer 222 for example from about 5 m to about 100 m, or from about 10 m to about 50 m, or from about 15 m to about 30 m in height.

Production well 202 is a height 254 above injection well 204 for example from about 5 m to about 100 m, or from about 10 m to about 50 m, or from about 15 m to about 30 m in height.

In some embodiments, height 232 is from about 70% to about 100%, for example from about 75% to about 95% of height 250.

In some embodiments, height 238 is from about 30% to about 70%, for example from about 35% to about 65%, or from about 40% to about 60% of height 250.

In some embodiments, height 254 is from about 30% to about 70%, for example from about 35% to about 65%, or from about 40% to about 60% of height 250.

FIG. 2 c:

Referring now to FIG. 2 c, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In some embodiments, a polymer mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, the polymer mixture has injection profile 208, and oil recovery profile 206 is being produced to well group 202.

In some embodiments, polymer mixture is injected into well group 202, and oil is recovered from well group 204. As illustrated, the polymer mixture has injection profile 206, and oil recovery profile 208 is being produced to well group 204.

In some embodiments, polymer mixture or a mixture including a polymer may be injected at the beginning of a cycle, and water may be injected at the end of the cycle to push the polymer mixture towards the producing wells. The polymer injection may follow a period of water injection, or the polymer mixture may be the first injectant into the reservoir.

In some embodiments, polymer mixtures injected into the formation may be recovered from the produced oil and/or gas and re-injected into the formation.

In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of at least about 5 centipoise, or at least about 10 centipoise, or at least about 25 centipoise, or at least about 50 centipoise, or at least about 75 centipoise, or at least about 90 centipoise. In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of up to about 125 centipoise, or up to about 250 centipoise, or up to about 500 centipoise, or up to about 1000 centipoise, or up to about 10,000 centipoise. In some embodiments, the oil may have a viscosity from about 150 to about 300 centipoise.

In some embodiments, the injected polymer mixture may have a viscosity from about 10 to about 200 centipoise, for example from about 25 to about 150, or from about 50 to about 125 centipoise.

In some embodiments, oil column 220 may have a horizontal permeability greater than about 10 milli-Darcies up to about three Darcies, up to about five Darcies, or up to about 10 Darcies. In some embodiments, oil column 220 may have a vertical permeability from about 0.3 to about 0.7 times the horizontal permeability.

FIG. 2 d:

Referring now to FIG. 2 d, in some embodiments, array of wells 200 is illustrated. Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).

In some embodiments, polymer mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, polymer mixture has injection profile 208 with overlap 210 with oil recovery profile 206, which is being produced to well group 202.

Releasing at least a portion of polymer mixture and/or other liquids and/or gases may be accomplished by any known method. One suitable method is injecting polymer mixture into a first well, and pumping out at least a portion of polymer mixture with gas and/or liquids through a second well. The selection of the method used to inject at least a portion of polymer mixture and/or other liquids and/or gases is not critical.

In some embodiments, polymer mixture and/or other liquids and/or gases may be pumped into a formation at a pressure up to the fracture pressure of the formation.

In some embodiments, polymer mixture may be mixed in with oil and/or gas in a formation to form a mixture which may be recovered from a well.

In some embodiments, a quantity of polymer mixture may be injected into a well, followed by another component to force polymer mixture across the formation. For example water in liquid or vapor form, water with a smaller amount of dissolved polymer to increase its viscosity, carbon dioxide, other gases, other liquids, and/or mixtures thereof may be used to force polymer mixture across the formation.

In some embodiments, from about 0.1 to about 5 pore volumes of the polymer mixture may be injected, for example from about 0.2 to about 2 pore volumes, or from about 0.3 to about 1 pore volumes of polymer mixture may be injected. The injection of polymer mixture may be followed by from about 0 to about 10 pore volumes of water, for example from about 3 to about 8 pore volumes of water.

FIG. 3:

Referring now to FIG. 3, in some embodiments of the invention, system 400 is illustrated. System 400 includes underground formation 402, formation 404, formation 406, and formation 408. Production facility 410 is provided at the surface. Well 412 traverses formation 402 and 404 has openings at formation 406 along the length of its horizontal portion. Portions of formation 414 may be optionally fractured and/or perforated. As oil and gas is produced from formation 406 it enters portions 414, and travels along and then up well 412 to production facility 410. Gas and liquid may be separated, and gas may be sent to gas storage 416, and liquid may be sent to liquid storage 418. Production facility 410 is able to mix, produce and/or store polymer mixture, which may be produced and stored in production/storage 430.

Polymer mixture is pumped down well 432 and then along its horizontal portion, to portions 434 of formation 406. Polymer mixture traverses formation 406 to aid in the production of oil and gas, and then polymer mixture, oil and/or gas may all be produced to well 412, to production facility 410. Polymer mixture may then be recycled, for example by utilizing a oil-water gravity separator, centrifuge, demulsifiers, boiling, condensing, filtering, and other separation methods as are known in the art, then re-injecting polymer mixture into well 432.

In some embodiments, a quantity of polymer mixture or polymer mixture mixed with other components may be injected into well 432, followed by another component to force polymer mixture or polymer mixture mixed with other components across formation 406, for example water in gas or liquid form; water mixed with one or more salts; other liquids; and/or mixtures thereof.

In one embodiment, from about 0.1 to about 2, for example from about 0.25 to about 1 pore volumes of polymer mixture may be injected into well 432. Then from about 0.5 to about 10, for example from about 1 to about 5 pore volumes of a polymer-water mixture having a viscosity at least about 25% less than the first polymer mixture, for example at least about 50% less than the viscosity of the polymer mixture may be injected into well 432. Then from about 1 to about 10 pore volumes of water may be injected into well 432.

In some embodiments, well 412 which is producing oil and/or gas is representative of a well in well group 202, and well 432 which is being used to inject polymer mixture is representative of a well in well group 204.

Polymer Mixtures:

In some embodiments of the invention, agents for increasing the viscosity of a flooding fluid mixture may be water-soluble or water-dispersible, high molecular weight polymers.

In some embodiments of the invention, agents for increasing the viscosity and/or increasing oil recovery may include one or more of:

1) Hydrolyzed Polyacrylamide, commercially available as Flopaam 3630S, Flopaam 3530S, Flopaam 3430S, Flopaam 3330S, Flopaam 3230S from SNF; Magnafloc 3336 from Ciba; Alcoflood 1275A, Alcoflood 1285REL, Praestol 2640SL, and Spurefloc AF1266; 2) polyvinylpyrrolidones; 3) hydroxyethyl celluloses; 4) cellulose sulphate esters; 5) guar gums; 6) xanthans; 7) scleroglucans; 8) polyacrylic acid polymers; 9) alkyl acrylamide polymers; 10) polysaccharide polymers; 11) copolymers of acrylamides and acrylic acid or sodium acrylate; 12) N-sulfohydrocarbon-substituted acrylamides; 13) biopolysaccharides; 14) copolymers of acrylamide and sodium acrylate; 15) solutions of partially saponified polyacrylamide; 16) copolymers containing from about 99 to about 50 percent by weight acrylamide units and from about 1 to about 50 percent by weight acrylate units; 17) polyacrylamide containing up to about 10 mole percent carboxylate groups; 18) random copolymers of 90 mole percent or more acrylamide and ten mole percent or less acrylic acid or acrylic acid salts; 19) homopolymers of N-methyl-acrylamide or N,N-dimethylacrylamide; 20) copolymers or terpolymers of 0.1-99.9 mole percent acrylamide and 99.9-0.1 mole percent N-methylacrylamide and/or N,N-dimethylacrylamide; 21) poly(methylmethacrylate), poly(ethylmethacrylate), poly(methacrylamide), poly(methylacrylate), poly(ethylacrylate), poly(N-methylmethacrylamide) and/or poly(N,N-dimethylacrylamide); 22) quaternary polymers with nitrogen or phosphorous as the quaternary or cationic atom with an aliphatic, cycloaliphatic or aromatic chain, where trivalent or tertiary sulfur may be substituted for the quaternary nitrogen or phosphorous in the polymers; 23) a polar and generally soluble polymer in polar solvents;

In some embodiments, the term “polyacrylamide” includes any cationic, anionic, nonionic or amphoteric polymer that may be comprised of acrylamide or methacrylamide recurring units. The polyacrylamides may be vinyl-addition polymers and may be prepared by methods such as by homopolymerization of acrylamide or by copolymerization of acrylamide with cationic, anionic, and/or nonionic comonomers. Suitable cationic comonomers include diallyldialkylammonium halides, the acid and quaternary salts of dialkylaminoalkyl(alk)acrylates and dialkylaminoalkyl(alk)acrylamides, for example the methyl chloride, benzyl chloride and dimethyl sulfate quaternary salts of dimethylaminoethylacrylate, dimethylaminoethylmethacrylate, dimethylaminoethyl-acrylamide, dimethylaminoethylmethacrylamide, and diethylaminoethylacrylate, for example diallyidimethylammonium chloride and the methyl chloride quaternary salt of dimethylaminoethylacrylate. Anionic comonomers may include acrylic acid, methacrylic acid, and 2-acrylamido-2-methylpropanesulfonic acid, and salts thereof, for example acrylic acid and sodium acrylate. Nonionic comonomers may include acrylonitrile and alkyl(meth)acrylates such as methylacrylate, methylmethacrylate, and ethyl acrylate. The polyacrylamides may also be formed by post-reaction of polyacrylamides in a manner well-known to those skilled in the art by reacting the polyacrylamide with a reagent capable of changing the chemical structure of the polymer. Post-reactions of polyacrylamide may include hydrolysis with acid or base to produce hydrolyzed polyacrylamide, Mannich reaction (optionally followed by quaternization to produce quaternized Mannich polyacrylamide), and reaction with hydroxylamine (or salt thereof) to produce hydroxamated polyacrylamide. Cationic and anionic polyacrylamides may be used.

In some embodiments of the invention, agents for increasing the viscosity include polymers comprising an N-vinyl lactam and an unsaturated amide, such as N-vinyl-2-pyrrolidone, including homopolymers, copolymers and terpolymers, as disclosed in U.S. Pat. No. 6,030,928, herein incorporated by reference in its entirety. In some embodiments of the invention, agents for increasing the viscosity include viscosifiers, such as polymeric thickening agents, that may be added to all or part of an injected water composition in order to increase the viscosity thereof.

In some embodiments, agents have a weight average molecular weight of from about 1×10⁶ to about 40×10⁶, for example from about 5×10⁶ to about 30×10⁶, or for example from about from about 4 to about 7 million or from about 15 to about 30 million. In some embodiments, the molecular weight is about 100,000 or greater, for example about 1,000,000 or greater, such as about 10,000,000 or greater. Molecular weights may be determined by light scattering, using commercially available instrumentation and techniques that are known in the art.

In some embodiments, agents are sold by a variety of companies including Dow Chemical Co. in Midland, Mich. One agent may be Alcoflood® 1235, a water soluble polymeric viscosifier available from Ciba Specialty Chemicals in Tarrytown, N.Y.

In some embodiments, the agent may be added to the water at a concentration of about 0.001% to about 1% by weight of the total solution.

The reduction of the mobility of a fluid in a porous media such as an oil-bearing reservoir can be accomplished by increasing the viscosity of the fluid, decreasing the permeability of the porous media, or by a combination of both. The agent may both increase the viscosity of water and/or reduce the permeability of a reservoir as a solution flows through it. The extent to which a particular concentration of a given agent performs these two functions may be very roughly a function of the agent's average molecular weight. The lower the permeability of the reservoir, the lower may be the average molecular weight of the agent which can be injected without significant wellbore plugging. For a given formation, however, it is entirely possible to have two partially hydrolyzed polyacrylamide solutions of the same average molecular weight which will exhibit radically different efficiencies for mobility control purposes. Where the molecular weight distribution of a polymer is relatively narrow, as is the case with some polymers, substantially all of the polymer may be effective in injectivity and mobility control. If the molecular weight distribution is broad, as is the case with some polymers, the mobility may be adversely affected by the lower molecular weight molecules in the polymer mixture, while the higher molecular weight molecules of the polymer indicate the presence of gel-like species that may result in wellbore plugging.

In some embodiments of the invention, agents for increasing the viscosity of the flooding water achieve a solution viscosity of at least about 10 centipoises at room temperature, and/or reduce the permeability of rock to the flooding water by adsorbing on the rock in the formation.

In some embodiments, agents may be selected based on viscosity retention, porous media flow performance, high temperature, high salinity, and high pressure conditions. In some embodiments, a solution with an agent may be at least five times more viscous than sea water.

In some embodiments, agents may be water-soluble or water-dispersible. In some embodiments of the invention, a composition includes an agent for increasing the viscosity, an aqueous fluid, and one or more of: surfactants, cosurfactants, corrosion inhibitors, oxygen scavengers, bactericides, and any combination thereof.

In some embodiments, a mixture of an agent and water may be subjected to shear forces in dynamic liquid dispersing or pumping devices such as centrifugal pumps. The mixtures can also be pumped in a loop so that they pass through the centrifugal pump several times until the desired polymer properties are obtained. Dynamic dispersing and pumping devices may be hydrodynamic flow machines, for example single- or multiple-stage rotary centrifugal pumps such as radial centrifugal pumps. Turbulent flow conditions are flow conditions characterized by irregular variations in the velocity of the individual liquid particles. A mixture may be passed through static cutting units with available water in order to provide a uniform slurry of particulate gel solids having a desired solids content without substantially degrading the agent, for example, reducing its molecular weight. The gel slurry resulting from passage through the static units may be either (a) introduced into a holding tank with gentle stirring for about 1-4 hours until the gel disappears and the agent dissolves to give a homogeneous solution concentrate at room temperature or slightly below, e.g., 15-20 C, or (b) the gel slurry may be fed continuously into a series of multiple hold tanks with sufficient overall residence time to form the homogeneous solution concentrate by the last hold tank. The homogeneous solution concentrate can then be passed through standard static mixers with available water for final dilution.

In some embodiments, the agent may be a polymer that may be prepared in the presence of crosslinking or branching agents, such as methylenebisacrylamide, and/or in the presence of chain transfer agents, such as isopropanol and lactic acid. As the amount of crosslinking agent is increased, the resulting aqueous composition of dispersed polymer tends to contain larger amounts of water-swellable polymer. As the amount of crosslinking agent is decreased, the resulting aqueous composition of dispersed polymer tends to contain lesser amounts of water-swellable polymer. Chain transfer agents tend to reduce polymer molecular weight and to render soluble polymers which would otherwise be water-swellable because of the presence of crosslinking agents. The aqueous compositions of the instant invention may contain water-soluble dispersed polymer or water-swellable dispersed polymer, or mixtures thereof.

In some embodiments, the agent may be a polymer, such as polyacrylamide, that may be prepared by using techniques such as polymerization in solution, water-in-oil emulsion, water-in-oil microemulsion or aqueous dispersion, for example water-in-oil emulsion or water-in-oil microemulsion. Polyacrylamide particles may be formed by methods such as by grinding or comminution of a solution-polymerized mass of dry polyacrylamide. Spray-dried polyacrylamide particles may be used and may be formed by spray-drying a polyacrylamide-containing dispersion, water-in-oil emulsion, or water-in-oil microemulsion.

In some embodiments, the agent may be a polymer, which may be mixed with water by contacting of the polymer particles with the moving stream of water so that it results in an aqueous composition comprised of about 0.01% or greater of dispersed polymer, for example 0.05% or greater, for example 0.1% or greater, for example 0.2% or greater, by weight based on total weight of said aqueous composition. In some cases the aqueous composition may contain more than 5% of dispersed polymer by weight, based on total weight of aqueous composition, but in other cases contains about 5% or less of dispersed polymer, for example about 2% or less, for example about 1% or less, on the same basis.

In some embodiments of the invention, agents for increasing the viscosity of the water include a small but effective amount of polymer used to produce the desired viscosity or other properties in the injection fluid. Based upon the properties of the formation and the intended nature and duration of the process, the type and amount of the agent may be selected to achieve the desired effects over the appropriate time period. In some embodiments, the amount of agent used will be in the range of from about 500 ppm to about 10,000 ppm, for example about 1,000 ppm to about 3,000 ppm, based on the weight of the injection fluid. Generally, there will be selected an economical amount and type of polymer to produce the desired effect for the required time.

In some embodiments of the invention, a composition comprising at least one water-soluble polymer may be prepared by combining at least one water-soluble polymer together in any sequence. The amount of water soluble polymer may be about 200 to about 10,000 ppm, for example about 250-500 ppm based on the entire combination. When the composition further comprises aqueous fluid, the aqueous fluid utilized will comprise or contain water and may be about 88 to about 99.91 wt % of the final combination. The composition may also contain other solvents, alcohols, and/or salts.

In some embodiments, the polymer solutions may contain the polymers in concentrations up to about 5000 ppm. Here, the upper concentration limit may be only due to the increasing viscosity, and the lower limit may be based on the increasing costs for recovery using larger amounts of more dilute solutions. For this reason, it may be preferable to use solutions having a polymer content up to about 3000 ppm, for example a polymer content from about 2000 ppm to about 3000 ppm. These solutions are then diluted after treatment in accordance with the invention to concentrations required for use of from about 300 ppm to about 2000 ppm.

Alternatives:

In some embodiments, oil and/or gas produced may be transported to a refinery and/or a treatment facility. The oil and/or gas may be processed to produce commercial products such as transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. Processing may include distilling and/or fractionally distilling the oil and/or gas to produce one or more distillate fractions. In some embodiments, the oil and/or gas, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.

Examples

A search was performed for viable EOR techniques for a group of medium heavy oil reservoirs with high permeability and a strong bottom aquifer. Typically these types of reservoirs have a poor primary oil recovery. Horizontal production wells drilled at the top of the oil column yield high (commercial) initial oil rates. However, these horizontal wells suffer from fast water breakthrough and subsequent oil production is at high water cut. Field characteristics pose a significant challenge to the application of EOR. These challenging characteristics include an oil column of around 40 m, a large and strong bottom aquifer, sustained high reservoir pressure (100 bar) and medium-high oil viscosity (250 to 500 cP).

Three EOR techniques were identified as having promise to increase ultimate recovery; in-situ combustion, high-pressure steam injection and polymer flood.

In-situ combustion (ISC) is generally applied to thin, confined and dipping sands in the absence of bottom water. Steam injection is normally applied at low reservoir pressure but has been evaluated for the reservoir pressure of 100 bar, yielding an a-priori low thermal efficiency. Hybrid processes combining steam and gas injection were tested in an effort to increase the thermal efficiency of the process. Finally, polymer is normally applied to oils with viscosity less than 100 cP. Adequate polymer injectivity is achieved using horizontal polymer injectors, these being optimally located to reduce chemical loss to the aquifer.

Comparison of these EOR processes is made in terms of simulated incremental recovery, economics, energy requirements and CO2 footprint and the feasibility of brown field implementation. Here, polymer flooding is shown to be the best option.

Field Description

The field under examination consists of several separate topographically flat oil bearing accumulations (so-called “reservoir highs”). The reservoirs are at a depth of ˜900 m below ground level are normally pressured having an initial pressure of approximately 100 bar. The reservoir fluid is a highly undersaturated 20° API medium heavy oil with low gas-oil-ratio (0.5 v/v) and viscosity in the range 250-500 cP at a reservoir temperature of 50° C.

The main productive unit comprises aeolian sands deposited in an arid continental setting. The main productive unit is a massive sandstone unit, with no further stratigraphic subdivisions because of its relative homogeneity. The sands are friable and unconsolidated, net average porosity is 27%, net average horizontal permeability over 5 Darcies and vertical permeability is estimated to be 0.3-0.7 times horizontal permeability. The top of the formation is unconformably overlain by another unit with similar properties to the formation and in excellent hydraulic communication. These two are thus considered as one single producing zone. Overlying these two are poorer quality sandy and shaly diamictites and a Cretaceous shale forming the structural top seal.

Early production began with a limited number of vertical wells. Later, horizontal wells were drilled at a spacing of 172 m before well spacing was reduced to an average of 86 m. FIG. 4 shows how the pace of drilling increased after 10-12 years of production. This resulted in a significant increase in gross production rate whereas watercut remained high, between 80-95%. This high watercut is due to the combined effects of unfavourable oil-water mobility ratio, typical stand-off from the OWC of only and an underlying, high permeability, regionally extensive, basal aquifer. Support from the aquifer is such that during the life of the field a limited pressure depletion of only 10 bar has been observed.

To date there are over 170 active wells in the field. Horizontal production wells are completed at the top of the reservoir so as to maximize distance from the aquifer. Horizontal completion intervals are typically 400 m to 550 m in length and the predominant completion type are pre-drilled liners (PDL) and wire-wrap screens (WWS). Recent developments have included the introduction of barefoot completion for wells and Expandable Zonal Inflow Profiler (EZIP) which provide a means of segmenting the completed interval. Beam pump is the preferred means of artificial lift although a small number of wells are completed with Electric Submersible Pump (ESP). Production facilities support the ongoing depletion development including gathering facilities, oil-water separation, oil dehydration, produced water treatment and deep aquifer disposal of produced water.

Requirement for EOR

A further reduction in well spacing was assessed, but found to have marginal benefit on ultimate recovery. As a consequence there is a requirement to consider EOR technologies. An initial screening exercise identified In-situ Combustion (ISC) and High Pressure Steam Injection (HPSI) as potential recovery processes suitable for a medium heavy oil. The present configuration of parallel horizontal wells is easily converted to a line drive configuration.

The characteristics of the field are such that for each of the three processes considered there is not one which can be easily applied, based on accepted screening criteria. A study was initiated with focus on the challenging aspects posed for each recovery mechanism (Table 1).

TABLE 1 A summary of the challenging aspects of EOR in the field Recovery Process Challenging Aspects In-situ Thick oil column & over-ride of combustion front combustion (upper limit 15 m) Strong bottom aquifer Flue gas confinement High Pressure Large aquifer, unable to reduce reservoir pressure Steam Injection Thermal efficiency Enhanced Higher oil viscosity than normally considered for Polymer Drive polymer (upper value of 150 cp) Chemical loss to bottom aquifer Horizontal well conformance Injection under matrix conditions required

In Situ Combustion (ISC):

ISC is probably one of the oldest EOR methods, proposed and tried in the field. However, it took many disappointing field experiences to understand better the key requirements for a successful ISC drive. ISC is a displacement process that requires good injectivity to sustain a robust combustion front. Furthermore, early oxygen breakthrough and poor sweep efficiency are key factors to take into account when ISC is considered.

Commercially successful projects in Suplacu de Barcau, Romania and in the Cambay Basin in Northwestern India (Balol, Shantal, Lanwa, and Becharaji) are line drives in thin dipping reservoirs where heat assisted gravity drainage results in excellent projected ultimate recoveries. The application of ISC in order to produce an oil column of thickness 40 to 60 meters in the presence of a strong bottom aquifer has not been practiced in the field. Moreover, development configurations for such a system are far from obvious.

Study Approach

A team was established with a objectives of investigating and ranking suitable EOR processes, demonstrate technical and commercial feasibility and proposing a maturation plan including requirements for field trial, as appropriate. The adopted workflow is to first establish a fundamental understanding of each EOR process, tailor the process to address the special characteristics of the field, develop a notional development plan and corresponding forecasts so that wells, surface facilities and operational requirements could be assessed.

Numerical simulations have been performed at several scales as appropriate to the various stages of the study. Taking for example, ISC, initial mechanistic simulation models were performed at the lab-scale to match and extract governing process parameters (fuel deposition, air requirement, reaction stochiometry and kinetics) from experimental data. Next followed a 2D conceptual pattern-scale modeling exercise to establish ISC modeling workflow and to complete an initial assessment of well spacing, configuration and required injection rates. Later, 3D conceptual and 3D geological sector models were constructed to take proper account of reservoir properties and topology. Forecasts from these models were scaled to a “field-scale” for screening level economics. Risks and uncertainties are expressed as a simple recovery range around a base case, informed by sensitivity analysis using sector models. Processes were ranked in terms of economics, recovery, net incremental recovery, CO2 footprint, energy requirements and ease of implementation.

EOR Options for Medium-Heavy Oil Reservoirs with a Strong Bottom Aquifer

In-Situ Combustion Description

Reservoirs with an oil column larger than 15 m, and a strong bottom aquifer require an alternative concept for an in situ combustion development. A top-down combustion drive is proposed to account for the tendency of gas override in heavy oil and to balance the aquifer. The aim is to force the combustion front downwards and reduce aquifer influx. The combination of top-down combustion and an optimized aquifer drive is the basis for the TAAD (Thermally Assisted Aquifer Drive) concept. In summary stage one is fast deployment of heat in top of reservoir by air injection at the top of reservoir (˜2 years), propagating a combustion front top-downwards. Stage two is characterised as a hot oil rim production, where the top of the reservoir in the combustion pattern is filled with flue gas

The first runs with a 3D conceptual model showed a poorer recovery during this last TAAD phase. The poorer performance of the TAAD phase was related to depletion of the gas zone and re-saturation of the gas zone. Gas production will move the oil rim into gas zone, resulting in locking oil as residual saturation. In addition increase of water production resulted in early watering out of the producer. The key to a successful TAAD stage is to balance the offtake of the aquifer and gas cap. In order to stabilise the oil rim gas (flue/inert) injection is proposed to maintain the gas cap and pressure, and thereby manage the oil rim after combustion. Optimisation of the gas-follow up schedule showed a gas rate reduced to 20% of the prior air injection rate is sufficient to maintain the gas cap. A gas rate constrained production scheme was required to control the gas production. In summary, after air injection, the produced flue gas replaces air and the gas injection rate is reduced to maintain the oil rim in place, allowing for controlled production of the hot oil rim.

Aside from the thicker oil column, driving an ISC development to a top-down drive, the remaining reservoir/crude properties screen nicely in favour of ISC. The crude viscosity is very much suitable for ISC and combustion tube experiments proved that the crude is suited for a stable HTO combustion mode. The coke deposited in the experiments perfectly match with the correlation of Prats to predict coke deposition based on the API gravity of the crude. The experiments also clearly showed the need for artificial ignition to initiate combustion in the reservoir.

ISC-TAAD Challenges

The air injection rate is the most important parameter in combustion projects. Firstly, because it governs both the requirement for air compression and the capacity of produced gas handling facilities it strongly impacts the economics. Secondly a too low injection rate can lead to die out of the front or to coking the formation due to LTO reactions. Because of the top-down design in a relatively thick oil column (>15 m), the required air rate is much higher than in a usual pattern or line drive ISC process. This is because much more air is required to burn the volume from top to bottom, as compared to the volume to burn in thin reservoirs in a line drive setting. The challenge to make ISC work, both technically and economically, for these reservoir conditions is to minimize the required air capacity by maintaining a high ultimate recovery.

Besides the ‘usual’ combustion challenges, i.e. front control, front die out and oxygen production, the TAAD concept has a specific challenge were flue gas confinement in a top-down drive is essential for the success of the recovery process. A 3D model was used to investigate possible oxygen and flue gas confinement issues in flat, pancake like reservoirs, where flue gas spreads easily, developing a strong override. Unless gas movement is restricted, i.e. by topographical confinement, the establishment of a top-down drive is uncertain. A number of options to solve the confinement issue were investigated, i.e. dedicated vent wells and water injection. Both were not successful in mitigating the spread of the flue gas. The impact on the combustion front by the presence of a vent well is enormous. The venting of the flue gas reduces the thickness of burned zone by a factor of two, thereby reducing the sweep in the pattern significantly. This finding has a major impact on the feasibility of the top-down ISC process. All existing wells in the reservoir have to be closed in order not to interfere with the ISC top down process if continued production with high GOR in existing wells is not possible. As a result, the ISC process presented here is therefore only applicable in small confined reservoirs.

ISC Pattern Configuration

The well configuration is most important for the deployment of ISC-TAAD. The injectors have to be located at the top of the structure and the producers half way in the oil column Based on a sensitivity study in 3D the optimal (economical and ultimate recovery) pattern consists of 2 horizontal production wells, approximately 500 m long, and 3 vertical air injection wells. The distance between the two horizontal producers is 75 m. FIG. 5 shows the single ISC pattern. The side elevation shows the difference in depth between the injectors and producers. Note that in a full field arrangement the ratio between injector and producer will be 3 to 1.

The option of a single horizontal injector was also considered, because it reduces the well count and it should result in a better sweep efficiency than vertical injectors. However a number of arguments are against this. 1) Artificial ignition of a combustion front along a horizontal well is very difficult. 2) Conformance of the injected air is hard to achieve. 3) Lack of control of the combustion front. Even with control valves it will be difficult to determine which zone causes breakthrough of oxygen in the production well. 4) The proposed ISC strategy is already adding complexity compared to a conventional ISC project. Only in one ISC project reported globally it is attempted to inject in horizontal wells and here a key enabler is spontaneous ignition of the crude. Here we propose 3 vertical injectors are proposed instead of one horizontal injection well.

ISC 3D Modelling and Results

A 3D model is used in order to generate more realistic and reliable forecasts for ISC. All model properties are kept the same as the 2D model, in order to evaluate the impact of a 3D geometry on the results. In addition, a 3D model with realistic geological properties was also generated.

In order to reduce runtimes and complexity of the simulation model, a single reaction approach (High Temperature Oxidation) was used to model combustion. The kinetics for this reaction are based on a match of actual combustion tube tests. In the model fuel (coke) is initially present in the oil column, based on the experimentally obtained fuel deposition. The crude is described by single component oil. The reaction rate is modelled by an Arrhenius type reaction, which is temperature dependent. The downside of this simplified model is the inability to properly account for different combustion regimes (LTO, HTO). Therefore, this model is not able to predict process failure due to the incorrect combustion regime, i.e. severe coking due to LTO reaction and the related diversion of the injected air stream. This limitation is accepted for screening purposes and a first pass of feasibility of ISC.

The workflow for 3D modeling is first to optimize the simulation runs based on the 2D model results. Here, optimisation includes both numerical and subsurface process optimization. The numerical optimization of the CMG STARS deck resulted in reduction of the runtime from more then 3 days to a few hours only. Then next, only a number of the optimized and most promising scenarios have been run using a 9-point discretisation scheme to check grid orientation effects. These same selected runs also have been run using the geological model. These final runs were used to generate the forecasts for evaluation of the ISC potential.

The full field forecast is generated using a simulation of 3 ISC patterns, shown in FIG. 6. The production profile from the inner pattern is taken to be representative for an ISC production well. The full field forecast is based on scaling of the production profile of this inner pattern. Unfortunately, because of model limitations, the conceptual model had to be used for the simulations. Therefore a sweep efficiency factor of 0.85 is applied to correct the forecast for (geological) heterogeneities. This factor is based on the difference between the geological and conceptual model results for a single pattern simulation. The size of a full high was assumed so that 12 horizontal producers can be laid out with 11 ‘rows’ of 3 injectors. The total air rate per phase is then 1,320,000 m3/day, given that the air rate for each well is 40,000 m3/day each. The air injection phase is 2.5 years and the gas follow up lasts 7.5 years, injecting only 20% of the initial rate. The incremental recovery at the end of the project is approximately 18% yielding a cumulative-Air-Oil-Ratio of 2000 m3/day.

High-Pressure Steam Injection Description

Similar to the ISC development, the optimal HPSI development is a top-down drive. Cyclic steam stimulation and SAGD strategies were also evaluated, but top-down HPSI clearly showed the highest potential for the reservoir under study. The top-down steam drive is illustrated schematically in FIG. 9. The key in this concept is to first inject steam in the bottom wells as a pre-soak phase (b). This establishes a hot fluid path of high mobility between the bottom and top wells. In the next phase (c) the bottom wells are converted to producers and top wells to injectors. A top-down drive is established with a good sweep efficiency, where gravity drainage is a key mechanism for recovery.

As an optional addition to the HPSI base case, a gas follow-up (d) is evaluated, whereby a non-condensable gas, such as flue gas, is injected. This aims to reduce steam requirements and in so doing increase the energy efficiency of the process. Oil in the column, by now hot, continues flowing to the bottom producers due to gravity drainage and pressure support of the gas, whose injection rate is adjusted to ensure voidage replacement of the produced fluids and condensation. The considerable energy savings of this option, however, come at the cost of the lower recovery and increased process complexity.

HPSI Challenges

The main challenge for a steam drive in reservoirs with a strong bottom aquifer is the thermal efficiency, which strongly depends on the pressure in the reservoir. Historical reservoir performance indicates that reservoir pressure cannot easily be lowered by aquifer pump off (APO). As a result steam temperature is high (300° C. at 90 bar) and the latent heat of steam is low; these effects combine to reduce overall thermal efficiency with increase heat losses from the reservoir. A further consideration is wellbore heat loss in injection wells, however assuming a completion with packer and a gas filled annulus we calculate heat losses to be acceptable—due to a gas-filled annulus and high injection rates in excess of 500 m3/d/well. Reservoir heat losses impact the lateral growth of the steam chamber. A challenge for the proposed steam development is steam conformance along the horizontal injection completion. Steam rate, steam quality, and inflow along the horizontal injector completion may require profile control devices such as venture choke, interval control values (ICV) or interval control devices (ICD). Present simulation work does not indicate a strong requirement for profile control but well costs estimates have assumed thermal-EZIP for well segmentation and multiple sliding sleeve devices allowing a limited means of controlling inflow. Further analysis would be required if this options were taken forward as the preferred concept.

HPSI Pattern Configuration

The well configuration of the top-down steam pattern is clearly shown in FIG. 9. A pattern consist of a horizontal well located a the top of the oil column and two horizontal wells located about half way down the oil column. After pre-steam-soaking the lower production wells, the top well is the steam injector and the other wells located in the oil column are switched to be oil producers. FIG. 10 shows a 3D model representing a element of symmetry (EOS). Also depicted in the same figure are the multiple steam patterns.

HPSI 3D Modelling and Results

The 3D model shown in FIG. 10 is build using a 2D model. It is extended to 3D using the same geological model as was used for our evaluation of ISC. Three top-down steam drive scenarios have been considered, scenarios are governed by differing assumptions of steam generation capacity:

-   -   In the base case scenario, a total of 2500 m³/d cold-water         equivalent (CWE) of steam generated by boilers is injected per         pattern, which comprises 3 steam injectors (replaced/converted         primary producers) at the crest, 8 primary producers and 10         thermal producers. As the steam front propagates from crest to         flanks and aquifer, the top (cold) producers shut-in         sequentially to prevent production of live steam and bottom         producers come on stream to capture the mobilised oil bank.     -   In the blanket scenario a total steam supply of 6000 m3/d CWE is         assumed, equivalent to the capacity of a typical steam         co-generation facility. In this case all of the top producers         are replaced or converted into steam injectors, which         corresponds to 11 steam injectors and 10 thermal producers per         pattern. Multiple steam chambers are formed around the         injectors, coalesce into a single steam chamber continuous         across the pattern and growing downwards as shown schematically         in FIG. 9.     -   A further scenario takes the base case but with a switch to         non-condensable gas after several years in order to provide         voidage replacement and pressure support while recovering the         still heated, mobile oil through bottom producers. Here we         consider injection of flue gas, a mixture of CO₂ (11 mole %) and         N₂ (89 mole %) resulting from combustion of CH₄ in the steam         generator.

Due to the energy challenge of a steam project a lot of effort was put in optimising the three top-down scenario's. The HPSI process is optimised with respect to oil recovery and energy efficiency (cOSR) using the following parameters:

-   -   Pre-soak is especially important to establish a thermal path         between the steam chamber and the bottom producers at the         beginning of the project. For this reason in the base case the         bottom wells in the centre of the pattern are steam pre-soaked         for 1 year before commencing top steam injection, whereas later         production wells do not require pre-soak. In the blanket case         all of the bottom wells are pre-soaked at the same time.     -   Well timing for producers is determined in the base case by the         speed of growing steam chamber, which drives the oil towards the         flanks and the aquifer. Each additional bottom producer should         come on stream just before the oil bank reaches it, because         opening the well too late would mean drawing the oil against the         steam drive. In practice the steam chamber grows laterally 86 m         (one well spacing) approximately every 18 months, which governs         the frequency of new wells.     -   Well depth. Thermal producers drilled too close to the OWC         suffer from increased watercut, whereas drilling the wells too         high in the oil column misses some of the displacement         efficiency due to a thinner steam chamber. The depth of 18 m, or         40% of the original column thickness, above the OWC was found to         be optimal.     -   Production well location is between the pre-existing water cones         (locations within the cones where oil saturation is typically 25         s.u. lower were not considered).     -   Producer off-take rate between 400-600 m³/d is optimal. Lower         rates allow oil to segregate between the well and the aquifer.         High rates excessively cool the production wells leading to an         increase in watercut.     -   Number of injectors and steam rate. In the base case, there is         no appreciable difference in reservoir performance using 1, 2 or         3 horizontal injection wells, however, 3 injectors provide         sufficient redundancy and realistic steam rates of just over 800         m³/d CWE per well. In the blanket case, 11 injectors operate at         uniform rates of about 550 m³/d CWE per well.     -   Steam quality. A downhole steam quality of 0.65 was assumed,         which is realistic for high-rate steam injection wells completed         with a packer.

For the gas follow-up HPSI case optimisations include:

-   -   Start of gas injection. An early gas follow-up benefits energy         efficiency at the expense of oil recovery, and vice versa. In         the base case, gas injection commences at the moment when the         HPSI process reaches its maximum cOSR.     -   Gas injection rate and profile. A total of 20,000 m³/d of flue         gas is required to achieve voidage replacement, however, a         higher gas injection rate of 75,000 m³/d was found necessary         during the first year of gas follow-up, in order to prevent the         aquifer influx in the bottom producers as a result of the         collapsing steam chamber. Such a tapered rate profile provides         near-identical oil production and cOSR as a constant rate of         75,000 m³/d, and it also benefits from the delayed gas         breakthrough by over one year and reduced gas throughput by a         factor of 4.

FIG. 11 shows the forecasts for a no further action case (NFA) (brown), HPSI base and blanket (red) and gas follow-up (orange) scenarios. All the scenarios have a common period of 5 years of primary production followed by 5 years of infill production. Steam pre-soaks start after 10 years of cold production and the top-down steam drive starts in year 11, when the first incremental oil response can be seen. The blanket case shows a significant acceleration of oil recovery compared to the base case as a result of the more aggressive steam injection policy. Gas follow-up starts after 5 years of steam injection, marked by a sharp increase in the cOSR (light blue) in year 15 and a flattening slope of the recovery curve. Quantitative results for oil recovery and cOSR of the HPSI and gas follow-up scenarios are summarised in Table 2.

TABLE 2 Comparison of the HPSI and gas follow-up scenarios based on the 3D geological element-of-symmetry model forecasts. Project end increm RF Net RF PV Net RF [%] [%] [%] Max cOSR Base 20.9 8.4 6.6 0.134 Blanket 22.9 9.9 8.6 0.135 Gas Follow-Up 21.6 12.6 9.3 0.182

All of the scenarios have a project lifetime shorter than 20 years ending when the amount of energy injected as steam or gas exceeds the amount of energy recovered as oil. HPSI recovery is high, reaching over 20% of STOIIP incremental over the NFA case, as a consequence of the good sweep efficiency in the permeable and relatively homogeneous reservoir. Nonetheless, despite a large effort on optimisation of the process efficiency maximum cOSR is below 0.14. The present-value (PV) net recovery factors accounting for time effects reflect the accelerated recovery of the blanket scenario, however, in practice the increase is offset by the additional well costs and the possibility of diverting extra steam capacity to another pattern in the base case.

The gas follow-up scenario provides a improvement over the HPSI base case in energy efficiency (OER up by 40%) and net recovery. On the other hand, detailed analysis of the gas follow-up process shows that it is applicable only in topologically confined areas, prone to early gas breakthroughs, and requires additional CAPEX on gas handling and compression equipment.

Polymer Injection Description

Polymer flooding in medium heavy oil reservoirs is the final option we evaluated. In order to provide a stable displacement a high polymer solution is required but low in-situ brine salinity means that required polymer concentrations are acceptable. Furthermore high permeability makes it possible to stretch the viscosity limit of a standard polymer application above normal upper limit i.e. 150 cP. A remaining challenge is the presence of a strong bottom aquifer as the high reservoir pressure results in difficulty in injecting the viscous polymer. Further, the comparatively thin oil column and the consequent proximity of injectors to the OWC mean that some polymer is lost to the aquifer, reducing the efficiency of the flood. A development concept is proposed where the impact of the aquifer influx is minimized. The development utilizes the assumed existing horizontal producers at the top of the oil column. This is different from the ISC and HPSI concept, where all pattern wells need to be newly drilled. In our concept additional horizontal injectors are drilled between existing producers and thus between existing water cones. To minimize losses of polymer into the aquifer, the injectors are drilled approximately midway in column (FIG. 12). A solution viscosity of about 100 cP is assumed in this concept.

Polymer Challenges

A polymer development in medium-heavy oil is not a straightforward polymer project. First of all the crude viscosity is outside the conventional range of application, so a high viscosity polymer slug is required to push the crude towards the producer. The strong bottom aquifer influx keeps the pressure high and impedes injectivity. In addition, due to the presence of a bottom aquifer the injected polymer could be lost to the aquifer. It is evident there will be some losses, but the well configuration should be chosen to minimise loses to the aquifer and maximize recovery. The aquifer influx itself also will cause mixing of aquifer water with the polymer solution, thereby diluting the solution and lowering the slug viscosity. Accounting for and managing the bottom aquifer is key for a successful polymer drive in this reservoir. Besides the aquifer, the use of horizontal injectors is also coming with a number of challenges. Well conformance is very important; a more or less even distribution of the polymer solution in the well is required to achieve a nice sweep of the pattern. The polymer drive is intended to sweep the reservoir on a short spacing and therefore matrix injection is essential. Taking into account the strong aquifer, again injectivity becomes a challenge.

Polymer Pattern Configuration

A number of well configurations were tested. The most important element in selecting the appropriate well configuration is the placement of the injector in the oil column and the well spacing. The options evaluated are shown in FIG. 8. Ideally an injector should be placed at the oil-water contact, exposing the entire oil column to the polymer (1). However, the presence of an extensive water leg will result in polymer being lost to the aquifer, reducing the efficiency of the process and increasing cost. The second configuration is set up to provide a balance between aquifer losses, and exposure of the oil column to the polymer (2). The third case is designed to limit the losses to the aquifer as much as possible (3). Also, the aquifer water would help in pushing the polymer towards the producers. However, not all of the oil exposed to the polymer and polymer breakthrough in the producers is expected to happen quickly. The last option evaluated is to locate the injector in the centre of the oil column under the producers (4). The rational behind this concept is to benefit from the pressure sink generated by the producers to encourage the injected polymer to move upwards, and reduce polymer losses to the aquifer. In addition, the aquifer water would find an easier path around the polymer slug, and mobilize any upswept oil between the producers.

The second concept is selected based on conceptual modelling in 3D using a simple homogeneous 3-D box model. The spacing between the producers is the same as for the ISC and HPSI concept; 75 m. This short well spacing provides a fast oil response, in the producers, to polymer injection. The selected well configuration is then taken through an optimization exercise using a 3D geological model.

Polymer 3D Modelling and Results

The polymer simulation model is based on the model used for ISC and HPSI. The same sector model was used and all the crude properties were identical (FIG. 13). A polymer phase was added to the model, where mixing with water is captured by a mixing rule. The geological model was used for optimisation of the selected concept (concept 2 in FIG. 13) with respect to injection rate, polymer viscosity and slug size injected. In this case, an optimum polymer viscosity is about 100 cP, and the injection rate 500 m3/day for a 500 m long horizontal well. The maximum injection pressure was set to 1000 kPa above the initial reservoir pressure. The incremental recovery of a polymer pattern is 11% with significant production acceleration (FIG. 14). The optimised concept was then used to evaluate the potential of polymer flooding and compared to the ISC and HPSI results.

Evaluation and Comparison of EOR Processes

Now we present a comparison of three EOR recovery methods (i.e. polymer, High Pressure Steam and ISC) on the basis of;

-   -   Net incremental recovery,     -   Energy efficiency and CO2 footprint     -   Ease of implementation     -   Target volumes     -   Economic comparison

Net Incremental Recovery and Energy Efficiency/CO2 Footprint

Polymer ranks best as having the highest net incremental recovery per pattern for an area of the field where the oil column thickness is 45 m (Table 3). Here we define energy efficiency in terms of the Oil Energy Ratio, where OER=produced oil volume (m3)/energy consumed (expressed as oil equivalent in gross heating terms. Our evaluation of energy efficiency takes into account only the main energy requirements of each process be they air compression (ISC), steam generation (HPSI) or water injection (polymer). There is no accounting for the energy provided to production facilities, for transportation etc. It is thus a simple calculation that provides a relative ranking. From the calculations we have performed it is clear, both energy efficiency and CO2 footprint are best for polymer.

It is interesting to note that HPSI is predicted to have the highest technical incremental recovery but once energy requirements are taken into consideration this advantage is lost and all three EOR processes have approximately equal net incremental recovery.

TABLE 3 Summary of incremental recovery, net incremental recovery, energy efficiency and CO2 emissions Incr. pattern Oil-Energy- Net incremen- CO2 EOR recovery Ratio tal recovery emissions option (% STOIIP) (m3/m3) (% STOIIP) (kg CO2/m3 oil) ISC 18% 10 15% 280 HPSI 29% 2 15% 1010 Polymer 17% 30 16% 67

Ease of Implementation, Impact on Existing Field Development and Risk Profile

We consider ease of implementation to comprise three key aspects; impact on the current field development, size, complexity and cost of additional facilities and the novelty of the EOR process (Table 4). Only the polymer option utilises existing wells and clearly outranks the other two processes in this respect. For all development concepts new facilities have to be built, which is typical for an EOR project, but the scope of polymer facilities without the requirement to accommodate high production and injection temperatures or high gas rates. The novelty ranking relates the particular configuration of the process in this field. There are novel aspects to all the processes. The polymer development relies on polymer injection in horizontal wells under matrix conditions and in addition polymer injection is rarely applied in medium heavy oil (>100 cP). All options are confronted with the strong bottom aquifer, which is taken into account in the well pattern configuration for each of them.

TABLE 4 Ease-of implementation for three EOR options Scenario Impact on existing development (wells) Additional facilities Novel Aspect ISC Adjacent wells shut-in or abandoned Air compression facilities Top down ISC New horizontal producers and vertical air (several MMm³/d, worlds Horizontal injection wells largest ISC) producers with ISC Flue gas handling system Pattern ISC Steam or electrical ignition HPSI Limited impact on existing wells, production Thermal injection and Top down steam continues until steam approaches production facilities, water process New horizontal producers + injectors (re-use treatment of existing wells as injectors not likely) Polymer Relatively straightforward, easily confined Water injection, (water Polymer using process. treatment), polymer handling horizontal wells >200 new injection wells in Nimr E and mixing facilities Matrix injection Bottom aquifer High oil viscosity

Target Volume

As previously discussed pattern-scale simulations have been scaled to the full-field. Through this exercise we find that the target volume for ISC is significantly less than the target volume for both polymer and steam. This relates to the gas confinement issues for our proposed ISC development. Only the six smallest highs can be developed to prevent the widespread passage of flue-gases through the reservoir which would interfere with areas of the reservoir still undergoing primary development.

Economic Comparison

For purposes of comparison we have used Unit Technical Cost (UTC) and found polymer to be the clear leader; UTC_(polymer)<UTC_(steam)<UTC_(ISC).

Polymer has the lowest facilities CAPEX of the three options comprising deep aquifer source wells, water injection & polymer facilities (polymer handling, mixing and distribution). Aquifer source water is selected on the basis of plentiful supply and elimination of the requirement to intensive cleaning of produced water. Compared to a conventional water injection development only polymer facilities are additional. Chemical OPEX might be expected to be prohibitive—the a high polymer slug viscosity is required to assure stable reservoir displacement, however reservoir salinity is low and high reservoir permeability allows choice of a high molecular polymer. Together these effects contribute to an acceptable polymer concentration (2000 ppm) which limits both the size of polymer facilities and recurring chemical costs.

Steam and ISC options are less attractive due to a requirement to drill new wells i.e. existing wells cannot be re-used. In particular the ISC option relies on a 3 injection wells per pattern with consequent high drilling CAPEX. For the steam option, operating cost per barrel is high due to a relatively low oil-steam-ratio and cost of energy to generate steam.

Polymer, the Preferred EOR Recovery Method

Based on the preceding evaluation it is clear that a polymer development scores greatest in terms of economics and practical application in the field. In terms of net incremental recovery it performs similarly to ISC and HPSI. Our proposed polymer development envisages installation of water injection and polymer facilities with water supply from deep aquifer supply wells. This water is non-potable but of low enough salinity (TDS=7000 mg/l) to be suitable as polymer mix water. A large number of new horizontal injection wells will be drilled between existing producers at a separation of 43 m. In each well the duration of polymer injection is short, typically 6 years, because of the close producer-injector well separation. Afterwards injection well and adjacent production wells are abandoned and injection is targeted towards a new area of the field so that development is phased over ca. 20 years. The inflow profile of all new injection wells will be measured and optimized using appropriate profile control technologies.

Illustrative Embodiments

In one embodiment of the invention, there is disclosed a method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer; drilling at least one horizontal production well near a top of the oil column; performing primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a location between the horizontal production well and a bottom of the oil column; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production well from the oil column. In some embodiments, the horizontal production well is at a distance of 25 meters to 100 meters from the horizontal injection well. In some embodiments, the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein the horizontal production well is at a location within 20% of the oil column height from the top of the oil column. In some embodiments, the method also includes a mechanism for injecting a water based mixture into the formation, after the water mixed with a viscosifier has been released into the formation. In some embodiments, the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein the horizontal injection well is at a location between 30% and 70% of the oil column height from the top of the oil column. In some embodiments, the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein a distance between the horizontal injection well and the horizontal production well is between 30% and 70% of the oil column height. In some embodiments, drilling at least one horizontal production well further comprises drilling an array of production wells comprising from 5 to 500 wells, and wherein drilling at least one horizontal injection well further comprises drilling an array of injection wells comprising from 5 to 500 wells. In some embodiments, each of the production wells are at a distance from about 50 m to about 100 m from each other, measured horizontally. In some embodiments, the oil column has a height from about 25 m to about 50 m, measured vertically. In some embodiments, the oil column comprises an oil having a viscosity from 50 to 250 centipoise, prior to the injection of the water mixture. In some embodiments, the horizontal production well comprises a water mixture profile in the formation, and the horizontal injection well comprises an oil recovery profile in the formation, the method further comprising an overlap between the water mixture profile and the oil recovery profile. In some embodiments, a first horizontal production well and a second horizontal production well comprise a pair of adjacent production wells which are separated by a horizontal production well separation distance, further wherein the horizontal injection well is located from about 40% to about 60% of the horizontal production well separation distance. In some embodiments, the viscosifier comprises a water soluble polymer. In some embodiments, the oil in the formation comprises a first viscosity, and the water mixture comprises a second viscosity, the first viscosity is within 75 centipoise of the second viscosity. In some embodiments, the oil in the formation comprises a first viscosity, and the water mixture comprises a second viscosity, the second viscosity is from about 25% to about 100% of the first viscosity. In some embodiments, the horizontal production well produces the water mixture, and oil and/or gas. In some embodiments, the method also includes recovering the water mixture from the oil and/or gas, if present, and then optionally re-injecting at least a portion of the recovered water mixture into the formation. In some embodiments, the water mixture is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins. In some embodiments, the oil column comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy. In some embodiments, the method also includes converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.

In one embodiment, there is disclosed a method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer, and at least two horizontal production well near a top of the oil column, which oil column has already undergone primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a vertical location between the horizontal production well and a bottom of the oil column, and at a horizontal location between the two horizontal production wells; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production wells from the oil column.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments of the invention, configurations, materials and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature. 

1. A method for producing oil and/or gas from an underground formation comprising: locating a suitable formation with an oil column located above an aquifer; drilling at least one horizontal production well near a top of the oil column; performing primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a location between the horizontal production well and a bottom of the oil column; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production well from the oil column.
 2. The method of claim 1, wherein the horizontal production well is at a distance of 25 meters to 100 meters from the horizontal injection well.
 3. The method of claim 1, wherein the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein the horizontal production well is at a location within 20% of the oil column height from the top of the oil column.
 4. The method of claim 1, further comprising a mechanism for injecting a water based mixture into the formation, after the water mixed with a viscosifier has been released into the formation.
 5. The method of claim 1, wherein the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein the horizontal injection well is at a location between 30% and 70% of the oil column height from the top of the oil column.
 6. The method of claim 1, wherein the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein a distance between the horizontal injection well and the horizontal production well is between 30% and 70% of the oil column height.
 7. The method of claim 1, wherein drilling at least one horizontal production well further comprises drilling an array of production wells comprising from 5 to 500 wells, and wherein drilling at least one horizontal injection well further comprises drilling an array of injection wells comprising from 5 to 500 wells.
 8. The method of claim 7, wherein each of the production wells are at a distance from about 50 m to about 100 m from each other, measured horizontally.
 9. The method of claim 1, wherein the oil column has a height from about 25 m to about 50 m, measured vertical.
 10. The method of claim 1, wherein the oil column comprises an oil having a viscosity from 50 to 250 centipoise, prior to the injection of the water mixture.
 11. The method of claim 1, wherein the horizontal production well comprises a water mixture profile in the formation, and the horizontal injection well comprises an oil recovery profile in the formation, the method further comprising an overlap between the water mixture profile and the oil recovery profile.
 12. The method of claim 1, wherein a first horizontal production well and a second horizontal production well comprise a pair of adjacent production wells which are separated by a horizontal production well separation distance, further wherein the horizontal injection well is located from about 40% to about 60% of the horizontal production well separation distance.
 13. The method of claim 12, wherein the viscosifier comprises a water soluble polymer.
 14. The method of claim 1, wherein the oil in the formation comprises a first viscosity, and the water mixture comprises a second viscosity, the first viscosity is within 75 centipoise of the second viscosity.
 15. The method of claim 1, wherein the oil in the formation comprises a first viscosity, and the water mixture comprises a second viscosity, the second viscosity is from about 25% to about 100% of the first viscosity.
 16. The method of claim 1, wherein the horizontal production well produces the water mixture, and oil and/or gas.
 17. The method of claim 1, further comprising recovering the water mixture from the oil and/or gas, if present, and then optionally re-injecting at least a portion of the recovered water mixture into the formation.
 18. The method of one claim 1, wherein the water mixture is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins.
 19. The method of claim 1, wherein the oil column comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy.
 20. The method of claim 1, further comprising converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.
 21. A method for producing oil and/or gas from an underground formation comprising: locating a suitable formation with an oil column located above an aquifer, and at least two horizontal production well near a top of the oil column, which oil column has already undergone primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a vertical location between the horizontal production well and a bottom of the oil column, and at a horizontal location between the two horizontal production wells; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production wells from the oil column. 